Barely hours before the deadline, Chevron received word from the US government that it would be allowed to continue operating in Venezuela. The original 6-month waiver from the US oil embargo against the South American nation was due to expire on July 27, and with little time to spare, the Trump administration finally agreed to extend it but only by 3 months.
Chevron, along with US service firms Halliburton, Schlumberger, Baker Hughes and Weatherford International – can now continue to operate legally in Venezuela until October 25. As a reprieve, that isn’t much. A mere waiver extension of 90 days will do little. Not long enough to stabilise the situation, but not short enough for major repercussions.
But at least for now, Chevron will be breathing a sigh of relief. The lone major US oil company still in operation after ExxonMobil and ConocoPhillips made a costly flee when Hugo Chávez nationalised the oil industry, Chevron raised some eyebrows as it curried favour with the Chávez government. At stake were crucial shares in key oil fields, including the vast Orinoco Belt and future opportunities in the country with the world’s largest proven reserves that exceed even Saudi Arabia. The vacuum left by ExxonMobil and ConocoPhillips was filled by Russia’s Rosneft and China’s CNPC, who receive crude shipments through complicated oil-for-loan deals. But Chevron is still holding on, supported mainly by Halliburton.
The main risk cited by Chevron as it lobbied for the waiver’s extension was that the assets it would be forced to give up would likely fall into the hands of Russian and Chinese firms, which would wipe out institutional American oil influence in the country. These fears appealed to the America First slant of the Trump administration, but only just. The necessity of the waivers was balanced against impatience to bring down the government of Nicolas Maduro. According to inside sources, Trump thought Maduro would cave in immediately following the sanctions; that this did not happen is a badge of embarrassment and the White House is apparently in no mood to capitulate and wants to force regime change soon.
Central to this equation is what the Venezuelan opposition, which the US recognises as the current legitimate government of the country will do. And Juan Guaido, the de facto leader of the National Assembly, has already announced that Chevron’s assets in Venezuela would be protected under his government. In other words, if Guaido became President, then there would be no problem. Russia and China wouldn’t be allowed to steal American oil interests from Chevron. But that is a big if. Guaido and his allies have already tried once to seize control, garnering international support for their cause but were repelled by Maduro and his incumbents. But pressure is still being applied, and the short tenure of the waiver could be seen as a sign that the US believes the Maduro regime will fall very soon.
And if it does, then Guaido would owe the US favours. And the price for US support is steep. Many American oil industry executives still remember the days of Venezuela’s ‘apertura petrolera’ period in the early 1990s, a golden age for US oil interests in Venezuela. In 1999, however the internationally-minded Rafael Caldera was replaced by leftist Hugo Chávez and those policies reversed, essentially kicking all US oil interests out of Venezuela. All, that is, except for shrewd Chevron. The battle waged by Trump’s White House is a war to return Venezuela to a pre-1999 state far more receptive to US influence. The question of which side will prevail is still up in the air, but for now, Chevron doesn’t have to choose a side yet.
Chevron's assets in Venezuela:
Something interesting to share?
Join NrgEdge and create your own NrgBuzz today
Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b
Headlines of the week
The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.
In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.
As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.
After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.
And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.
So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.
Supermajor Financials: Q2 2019
Source: U.S. Energy Information Administration, CEDIGAZ, Global Trade Tracker
Australia is on track to surpass Qatar as the world’s largest liquefied natural gas (LNG) exporter, according to Australia’s Department of Industry, Innovation, and Science (DIIS). Australia already surpasses Qatar in LNG export capacity and exported more LNG than Qatar in November 2018 and April 2019. Within the next year, as Australia’s newly commissioned projects ramp up and operate at full capacity, EIA expects Australia to consistently export more LNG than Qatar.
Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) in 2011 to more than 11.4 Bcf/d in 2019. Australia’s DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d by 2020–21 once the recently commissioned Wheatstone, Ichthys, and Prelude floating LNG (FLNG) projects ramp up to full production. Prelude FLNG, a barge located offshore in northwestern Australia, was the last of the eight new LNG export projects that came online in Australia in 2012 through 2018 as part of a major LNG capacity buildout.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL), trade press
Note: Project’s online date reflects shipment of the first LNG cargo. North West Shelf Trains 1–2 have been in operation since 1989, Train 3 since 1992, Train 4 since 2004, and Train 5 since 2008.
Starting in 2012, five LNG export projects were developed in northwestern Australia: onshore projects Pluto, Gorgon, Wheatstone, and Ichthys, and the offshore Prelude FLNG. The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In eastern Australia, three LNG export projects were completed in 2015 and 2016 on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.4 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane as a feedstock to produce LNG.
Source: U.S. Energy Information Administration
Most of Australia’s LNG is exported under long-term contracts to three countries: Japan, China, and South Korea. An increasing share of Australia’s LNG exports in recent years has been sent to China to serve its growing natural gas demand. The remaining volumes were almost entirely exported to other countries in Asia, with occasional small volumes exported to destinations outside of Asia.
Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL)
For several years, Australia’s natural gas markets in eastern states have been experiencing natural gas shortages and increasing prices because coal-bed methane production at some LNG export facilities in Queensland has not been meeting LNG export commitments. During these shortfalls, project developers have been supplementing their own production with natural gas purchased from the domestic market. The Australian government implemented several initiatives to address domestic natural gas production shortages in eastern states.
Several private companies proposed to develop LNG import terminals in southeastern Australia. Of the five proposed LNG import projects, Port Kembla LNG (proposed import capacity of 0.3 Bcf/d) is in the most advanced stage, having secured the necessary siting permits and an offtake contract with Australian customers. If built, the Port Kembla project will use the floating storage and regasification unit (FSRU) Höegh Galleon starting in January 2021.